1. Field of the Invention
The invention relates to safety equipment, for an underground petroleum production well, and, more particularly, to an annular safety system to prevent blowout of a well equipped for gas lift operation, said safety system including a wireline release hanger with gas injection mechanism and allowing for retrieval of the system and related downhole production equipment from downhole.
2. Description of the Related Art
Much of the petroleum well drilling and completion technology presently employed has been practiced for a number of years. In general, there are two drilling methods employed for drilling petroleum production wells. One type of drilling, termed cable tool drilling, is presently employed only infrequently. In cable tool drilling, a chipping tool attached to a cable is repeatedly lifted by the cable and then dropped onto a sedimentary formation to form a hole in the formation. The impact from dropping the tool chips ,away the sediments to create and deepen the hole to a desired depth. Cable tool drilling is generally effective only for very shallow drilling in particular, limited types of sedimentary formations.
A second type of drilling, referred to as rotary drilling, is the most common form of drilling employed today. Rotary drilling has today virtually replaced cable tool drilling. Rotary drilling was first employed in the United States sometime around the year 1900. In rotary drilling, the drilling action comes from pressing teeth of a drill bit firmly against a sedimentary formation and turning, or rotating, the bit. Several types of bits are commercially available, most having protruding teeth formed of a very hard material capable of cutting away at the sedimentary formations being drilled. At the same time this type of bit is rotated, a fluid, usually a liquid concoction of clay and water called drilling mud, is forced at great pressure out of special openings, or nozzles, in the bit. Due to the pressure, this mud jets out of the bit nozzles with great velocity. These jets of mud then move cuttings made by the bit teeth away from the teeth, and thereby continuously expose fresh, uncut sediments to the teeth. Once the cuttings are moved away from the bit teeth, the mud lifts the cuttings off the bottom of the hole cut by the drill and then carries the cuttings up the drilled hole to the ground surface for disposal.
The rotary drill can drill a subsurface hole to depths in excess of 20,000 feet. As the depth of a drilled subsurface hole increases, pressures encountered at the deepening bottom of the hole tend to rise. The pressures increase in this manner due, for example, to the weights of the sedimentary layers atop the depths. Due to the tremendous weights of sedimentary layers and other factors, pressures at the bottom of a well hole are often extremely high. Due to these tremendous pressures, oil and/or natural gas wells must typically be "completed" in some manner to prevent cave-in of the well hole and to allow for and control flow of oil and/or gas from deep sedimentary zones containing the oil and/or gas.
A wide variety of well completion methods and types are possible. In an example of a common arrangement, the well is "cased" and "cemented". The process of casing a well typically involves placing steel pipe, referred to as casing, within the drilled hole, i.e., wellbore, of an oil and/or gas well. The casing process is typically performed at particular intervals as drilling of a well progresses. The purpose of the process is to prevent the walls of the drilled hole from caving or sloughing during drilling and to provide a means for extracting oil and/or gas from downhole in the well if the well is determined to be sufficiently productive. The casing utilized in a particular instance for the process is typically smaller in outside diameter than the diameter of the drilled hole. Depending on the requirements for satisfactorily completing a particular well, there may be several strings of casing, one inside the other, placed in the wellbore.
Once the casing or a particular string thereof, as the case may be, has been inserted inside the wellbore of the drilled hole, the well is often then also cemented. The process of cementing a well usually involves pumping a liquid slurry of a special cement into the annular space formed between the casing and the wall of the drilled hole. In the typical cementing process, the cement is pumped through drillpipe positioned in the wellbore, to the bottom of the casing and up into the annular space. The cement is allowed to harden creating a drill hole wall comprising the casing pipe and cement.
Once a well has been cased and cemented, a special piping, commonly referred to as tubing, is often then run into the well inside the cemented casing. Tubing generally consists of a series of lengths of seamless pipe, each length having screw threadings at each end on the outside circumference thereof. The lengths are strung together in a series by couplings, which are short pipe fittings with both ends threaded on the inside circumference. The tubing, as inserted in the drilled hole, serves as a passageway for the migration of oil and/or gas from productive sedimentary formations at locations downhole.
Tubing strings are often of significant length since the strings must extend at least from the vicinity of those productive sedimentary formations to the ground surface. Strings of such length can be very weighty. These strings typically must be suspended in some manner from the well casing. If the tubing string is suspended from the top of the casing, that portion of the casing is subjected to the entire weight of the string. It is, therefore, desirable in the case of certain wells to instead suspend the tubing string from the casing at one or more vertical locations within the well, between productive formations and the ground surface. By so suspending the string at those one or more vertical locations within the well rather than at the top of the casing at the ground surface, the weight of the tubing string may be distributed along the vertical length of the casing.
A variety of presently available devices may be employed to effectively suspend a tubing string from well casing. Devices by which the tubing string may be so suspended are sometimes referred to as hangers. The heretofore available hangers typically are incorporated with the casing as the casing is inserted during the process of casing the well. Those hangers then serve to suspend the tubing string from desired locations along the length of the casing to prevent the tubing string from falling deeper into the wellbore. In the case of these heretofore available hangers, the tubing string is only prevented from falling deeper into the wellbore, not from moving upward in the wellbore towards the ground surface. That upward movement is possible because those heretofore employed hangers have not been equipped to also restrict upward movement of the tubing string. This is probably so, at least in part, because there has previously been no reason that restriction of upward movement of the string would be desired.
Further regarding the tubing string, the outside diameter of the tubing inserted in the drilled hole is usually smaller than the inside diameter of the casing. The result of these differing diameters is typically the existence of an annular space between the tubing and the casing along the corresponding lengths thereof. This annular space between the tubing and the casing can be selectively sealed by various packers to prevent the flow of produced oil and/or gas in the annular space. The term packer typically refers to some type of expanding plug which is positioned and then expanded mechanically, hydraulically, or by other means to seal off select sections of casing, for example, annular spaces between casing and tubing. A variety of types of packers are commercially available. Most available packers consist of a sealing device, a holding or setting device, and an inside passage for flow of fluids, such as oil and/or gas.
Once the wellbore is cased and cemented and tubing and packers, as desired, are positioned in the well hole, oil and/or gas production from the well may be commenced by making holes through each of the tubing, casing and cement in the vicinity of select regions of the sedimentary formations believed to contain producible quantities of oil and/or gas. The process of making those holes through the tubing, casing and cement is referred to as perforating the well. A variety of methods and devices may be employed to perforate the well. In a typical method, a perforating gun is employed. A perforating gun is a device which may be lowered through the tubing into the well hole and, in the common case, caused to shoot bullets or set off special explosive charges known as shake charges. The bullets or shake charges are caused by the gun to be discharged at various circumferential and vertical positions within the tubing. The discharged bullets or shake charges pierce the tubing, casing and cement and create pathways some distance into the sedimentary formation in the select regions.
Once a well has been perforated, oil and/or gas from the sedimentary formation in the regions of the perforations migrates through the formation into those pathways, then through the perforation holes in the cement and casing and into the tubing. Within the tubing, the oil and/or gas travels from the location of the perforations downhole, upwards to the surface of the ground. The oil and/or gas so migrates and travels upwards to the surface due to the pressure gradient from higher pressure at the productive sedimentary formation to progressively lower pressure towards the top of the well at the ground surface.
At the ground surface of the well, the top of the casing typically protrudes some distance above the ground forming the so-called casinghead. Various control valves and flow pipes are usually attached to this casinghead to confine, regulate and control the flow of produced oil and/or gas. These valves and pipes are often also equipped with a variety of pressure gauges and chokes to prevent blowout and leakage of the produced flows. A variety of types and configurations of these valves, pipes, gauges, chokes, and other devices are presently available to be employed with a well. Due to the branching arrangement of many of these configurations, the configurations are often referred to as Christmas trees.
Often, old wells, wells in particular locales, deep wells, and certain other wells require special operation procedures referred to as improved recovery techniques. There are a variety of these recovery techniques presently employed for oil wells. One such recovery technique is gas lift operation. Gas lift is the process of raising or lifting fluid from a well by injecting gas down the well through the tubing or through the tubing-casing annular space. The injected gas aerates the fluid being produced so that the fluid then exerts less pressure than that of the producing formation. Consequently, the higher pressure of the producing formation forces the fluid being produced through the tubing, from downhole in the vicinity of the producing formation towards the surface, thereby improving recovery of the fluid. In a gas lift system for gas lift operation of a well, gas may be injected continuously or intermittently, depending on the producing characteristics of the well and the particular arrangement of the gas-lift equipment.
As will hereafter be more fully described, in the typical gas-lift operation, the annular space between the tubing and casing is entirely filled with injected gas during gas-lift operation. In such an arrangement, a large amount of gas is present within this annular space at any given time. This large amount of gas in the annular space is believed to create certain potential operational hazards in some wells employing gas -lift techniques. One example of these potential hazards is leakage of injected gas from the well hole, for example, due to the wellhead being knocked off. Leaked gas could ignite, thereby also igniting the large amount of gas within the annular space. The result could be a destructive and potentially deadly explosion. Some believe the tremendous explosion and fire at the Piper Alpha site in the North Sea may have resulted from circumstances similar to those described.
Because of these and other potential hazards of gas lift operation of wells, various governmental regulatory and other restrictions have been imposed requiring in many cases that wells employing gas lift operation include certain safety mechanisms designed to reduce and/or eliminate the hazards. For example, North Sea oil operators must now include a form of annular safety mechanism in their North Sea well completions fitted for gas lift operation. Such an annular safety mechanism must serve to seal off flows from a well in the event of certain triggering occurrences indicative of particular potentially hazardous situations. Some operators in seeking to comply with those requirements have undertaken to position annular safety valves downhole which may serve to isolate and seal gas lift gas within the casing-tubing annular space. In those well arrangements employing annular safety valves, the well tubing is also affixed with a safety valve. Control equipment employed in those well arrangements can cause both the annular safety valves and the tubing safety valve to close, isolating gas and oil downhole, in the event of triggering circumstances indicative of hazardous situations. These previously employed annular safety valve/tubing safety valve arrangements, nevertheless, can present obstacles and difficulties to operators when performing various well workover and maintenance operations.
Well workover is a generic term used to describe one or more of a variety of remedial operations on a producing well to try to increase production. Well workover is a common operation performed by well operators. In many cases, workover operations require some type of downhole equipment which must be manipulated and activated downhole within the wellbore. Like workover operations, well maintenance and repair operations must also often be performed downhole within the wellbore. Maintenance and repair operations are typically directed to wellhead and downhole equipment in efforts to keep that equipment in proper working order. Some examples of workover and maintenance and repair operations are deepening, plugging back, pulling and resetting liners, and squeeze cementing. In each of these instances and in most others as well, various tools must be employed downhole within the wellbore in order to produce desired results from the operations.
Since well workover and maintenance and repair operations often require that certain activities be performed downhole within the wellbore, it is helpful to the operator if the well equipment arrangement allows relatively easy access to downhole areas. The annular safety valves/tubing safety valve arrangements heretofore employed in completing wells for gas lift operation can restrict and complicate workover and maintenance and repair procedures. In particular, in order to lower a tool downhole for many of these type procedures, the tool must be lowered into the well through the annular space between the casing and tubing or, if that is not possible, through the tubing string. If the operation is performed in the annular space between the casing and tubing by lowering a tool into that annular space, the valve arrangements of those wells so completed require that the operator remove the entire annular safety valve mechanism from the wellbore to allow passage of the tool. If, on the other hand, the annular space between the casing and tubing can not be entered to perform the downhole operation, then the operation must be performed by entering the tubing string to reach the downhole region for the operation. When a tool is lowered into the wellbore through the tubing, the tubing can be damaged by the tool or may present obstacles to passage of the tool, for example, due to sludge and other crud which has accumulated in the tubing from produced fluids. In either case of operations in the annular space or in the tubing, the previously employed valve arrangements in wells completed for gas lift operation present problems to the operator.
Further, downhole safety valves, such as the annular safety valves and tubing safety valves employed by operators in gas lift operations, tend to be the equipment likely to wear out and require maintenance in most wells. The annular safety valve/tubing safety valve arrangements heretofore employed in wells completed for gas lift operation make replacement of those valves an involved and costly procedure. In particular, the wells must be sealed off in some manner to prevent flow of the pressured oil and gas from the well as the valves are removed. This sealing off is a particular problem when the annular safety valves must be replaced or repaired. In that case, a mechanism separate from those valves must be employed to retain injected gas lift gas within the annular space between the casing and tubing to prevent the gas from escaping the wellbore. As previously briefly mentioned, the typical completion arrangements of these wells do not provide a means which prevents the downhole equipment of the well from being raised within the wellbore. Also as hereinbefore briefly mentioned, the volume and pressure of the injected gas in the annular space between the casing and tubing is typically quite great. Consequently, any mechanism employed to retain the gas within the wellbore of these wells must be operable independent of the annular safety valves being serviced, must be sized to precisely seal off the wellbore and yet be strong and reliable to overcome and retain the great gas volume and pressure, and can not rely upon affixation to the downhole equipment of the well as that equipment has not been secured within the wellbore to prevent the equipment from being raised. The previously available mechanisms for use in those situations with these wells completed for gas lift operation have not proven adequate.
Finally, in those previous annular safety valves/tubing safety valve arrangements in wells completed for gas lift operation, the tubing safety valve has generally been located uphole from the annular safety valve mechanism. In those wells, access through the annular space between the casing and tubing to service the annular safety valve mechanism or other downhole equipment is obstructed. The tubing safety valve where attached with the tubing typically occupies a greater cross sectional area than does the tubing alone. Wellbore cross section is typically limited after casing and cementing is completed, therefore, space for downhole operations is confined to that limited area. The increased cross-sectional area of the tubing safety valve where attached with the tubing will, in many cases, not leave sufficient space for passage of downhole tools through the annular space between the casing and the tubing. Thus, in these described arrangements, the tubing safety valve must be removed in order to perform wellbore operations downhole of the tubing safety valve. The complications and hazards of that removal have been previously described.
The present invention overcomes these and other problems presented by the prior annular safety valves/tubing safety valve arrangements in wells completed for gas lift operation. Because the present invention overcomes those problems, the invention is believed to be a significant advance in that technology.